Helmerich & Payne, Inc.
Q3 2015 Earnings Call Transcript

Published: 30 Jul 2015

[Operator:]

Good day, everyone, and welcome to the third quarter earnings conference call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the Q&A session. Please note, today's call is being recorded. It is now pleasure to turn the program over to Juan Pablo Tardio, Vice President and CFO. Please go ahead.

[Juan Pablo Tardio:]

Thank you and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the third quarter of fiscal 2015. The speakers today will be John Lindsay, President and CEO; and me, Juan Pablo Tardio. Also with us today is Dave Hardy, Manager of Investor Relations. As usual, and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's Annual Report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call over to John Lindsay.

[John W. Lindsay:]

Thanks, Juan Pablo, and good morning, everyone. Thank you for joining us on the call this morning. You may recall at the time of our last conference call in April, the U.S. land rig count was still declining at a steep rate and we were reluctant to call a bottom. There have been several indications since then that the trough was approaching, and the rig count did appear to bottom out, but today, seeing oil prices decline by over $10 per barrel over the past several weeks, that bottom could soon prove to be false. This is unfortunate for all of us in the energy sector who had hoped to see at least some recovery in the back half of 2015. The industry has idled over 1,150 rigs in the U.S. since the peak rig count in 2014. That's made up of approximately 720 legacy SCR and mechanical rigs and approximately 440 AC drive rigs. H&P alone has idled over 180 AC drive FlexRigs. While cost management in this kind of declining environment becomes a company-wide priority, the challenge is to initiate reductions with the right balance. That undertaking involves right-sizing the organization as well as preserving our FlexRig assets for the future. One important aspect in the process is avoiding indiscriminate reductions that unduly damage our capacity to readily respond to a reversal in market conditions. Although Juan Pablo is going to address expenses in a moment, I want to mention that much of the quarterly expense per day increase is associated with our systematic approach to idling our AC FlexRigs. During the 2008 and 2009 downturn, we identified several best practices for idling AC rigs and preserving equipment integrity. We put those learnings into practice when the downturn began. There are three points I want to underscore relating to this process. First, our currently idled fleet is worth billions of dollars in terms of replacement value. We take great care to preserve that value. Second, a portion of that preservation effort entails operating, maintenance and security procedures, which does add to our per day expense. Could we delay that expense today? Perhaps some of it, but we see our approach as a long-term investment in our FlexRigs. It's a case of pay me now or pay me more later. Finally, the replacement cycle will continue. As the industry's high-grade process moves forward, our ability to respond in a timely and efficient manner will position the company for more opportunities and will ultimately allow us to provide greater value to customers. Our rig preservation process enables our FlexRigs to be prepared to work when the customer is ready. We believe, in terms of speed and scope, our ability to place rigs back into service during the last recovery created significant value for our shareholders. That quick response capability remains one of our key goals today. Our fleet profile is a competitive advantage. The FlexRig design allows us to provide a family of solutions for our customers. We have over 310 AC drive FlexRigs with 1,500 horsepower rating which represents over 90% of our U.S. land fleet. In many of the basins we work, the requirement is for longer laterals, multi-well pads and higher horsepower specifications. We have over 180 pad-optimal FlexRigs with 1,500 rating, AC drive power systems, multi-well pad capability and, to a significant extent, 7,500 psi mud systems. Today and in the future, our organization remains focused on supporting our customers through innovations to our service offering as well as upgrades to our fleet as needed. Not all rigs require multi-well pad and/or 7,500 psi systems today, but as we have outlined on previous calls, we are seeing preferences shift and more E&P companies are choosing AC drive technology for horizontal, unconventional resource drilling. AC drive rigs continue to replace legacy rigs and today have over 50% of the U.S. land industry market share, and that's up from 40% at the peak last year. There are significant competitive advantages for H&P by having a standardized, modern fleet of AC drive FlexRigs. We're able to leverage the learnings we capture and provide greater efficiencies, reliability, safety and savings for our customers. We've been fortunate to have picked up over 10 new customers this year, and that new customer adoption is a result of our performance and reliability. Before turning the call back over to Juan Pablo, I want to address the outlook for activity for the rest of 2015. We know better than to try to predict oil prices or rig counts, so I won't attempt that today. I will share a few anecdotal experiences from the past few weeks, the tone from the customer of what may happen assuming oil prices don't improve from here. First, we've seen instances where some customers have, at least for now, backed off of plans for reactivations in the second half of 2015. Secondly, some customers believe it's reasonable to assume that the current U.S. land rig count may not be sustainable with WTI oil priced in the $40s. Finally, operators remain disciplined with respect to their budgets, and they plan to spend within cash flow, and lower commodity prices mean fewer wells drilled. This remains a very challenging environment, but we believe the company is well-positioned. Long-term contracts continue to protect our investments. The balance sheet's in great shape. Our customer base remains strong and our competitive advantages have positioned us to manage through this cycle and to capture opportunities when they emerge. Now I'll turn the call back over to Juan Pablo, and he'll make a few comments regarding the results of our third fiscal quarter and some remarks related to the outlook for the fourth fiscal quarter.

[Juan Pablo Tardio:]

Thank you, John. The company reported $91 million of net income, $130 million in operating income and $660 million in revenue during the third quarter of fiscal 2015. As expected, these quarterly levels were down significantly as compared to with prior quarter. Following are some comments of each of our drilling segments. Our U.S. land drilling operations delivered approximately $122 million in segment operating income during the third fiscal quarter. The number of quarterly revenue days significantly declined, resulting in an average of approximately 156 rigs generating revenue days during the third fiscal quarter and representing a 32% decline in revenue days as compared to the second fiscal quarter. On average, approximately 128 of these rigs were under term contracts and approximately 28 rigs worked in the spot market. Excluding the impact of early termination revenues, the average rig revenue per day decreased by 3.4% from the second fiscal quarter to $26,634 in the third fiscal quarter and the average rig expense per day increased by 5.5% to $14,130, resulting in an average rig margin per day of $12,504 in the third fiscal quarter. The decline in average rig revenue per day was attributable to softer market conditions and to mutually beneficial temporary day rate reductions for some rigs that are under long-term contract. Those temporary day rate reductions were granted in exchange for additional term durations at fully priced day rates, also fully protecting the backlog for the corresponding rigs and effectively extending the duration of the corresponding work. The increase in the average rig expense per day was primarily a result of the high volume of idled rigs and related efforts to be cost-effective through the cycle and well-positioned for a potential industry recovery. During the quarter, the segment generated approximately $76 million in revenues corresponding to long-term contract early terminations. Given existing notifications for early terminations, we expect to generate less than $4 million during the fourth fiscal quarter and about $23 million thereafter in early termination revenues. Since November of last year and excluding some rigs working for customers that decided not to early terminate the contracts as per prior written notice to us, we have received early terminations for a total of 47 rigs under long-term contracts in the segment. Total early termination revenues related to the 47 contracts are now estimated at slightly under $200 million, approximately $87 million of which corresponds to cash flow previously expected to be generated through normal operations during fiscal 2015, $62 million during fiscal 2016, and $49 million after that. As of today, our 342 available rigs in the U.S. land segment include approximately 156 AC drive FlexRigs generating revenue and 186 idle rigs, including 179 idle AC drive FlexRigs. Included in the 156 rigs generating revenue are 124 rigs under term contracts and 32 rigs in the spot market. The 156 rigs generating revenue include some rigs that are on standby type day rates and some newbuild deliveries that have been delayed in exchange for compensation from customers. Note that these delayed newbuild rigs do not yet generate revenue days. Since our last conference call in late April, the number of FlexRigs on standby type day rates has significantly declined, as over half of those have returned to work. Looking ahead to the fourth quarter of fiscal 2015, we expect revenue days to decrease by about 3% to 4% quarter-to-quarter. Excluding the impact of revenue corresponding to early terminated long-term contracts, we expect our average rig revenue per day to decline to roughly $26,000. The average rig expense per day level is expected to decline to roughly $13,900 as we continue to manage the transition towards what we expect to be a more stable level of activity during the next few months. Subject to additional early terminations and excluding rigs that we have reduced early termination notifications for, the segment already has term contract commitments in place for an average of approximately 120 rigs during the fourth fiscal quarter and an average of about 108 rigs and 82 rigs during fiscal 2016 and fiscal 2017 respectively. The recent and mutually beneficial negotiations of some long-term contracts that resulted in reduced day rates in exchange for additional term durations at fully priced levels impacted the average rig margin per day level for all rigs on term contract by less than 5%. This average for rigs that are already under term contracts is expected to remain strong and roughly flat during the next several quarters as some rigs roll off and newbuilds are deployed. The average is expected to once again increase to previous levels when the mentioned day rate reductions expire and the remaining term contract durations from those contracts begin to once again apply. The average pricing per rigs in the spot market declined by approximately 7% from the second to the third quarter of fiscal 2015 and is expected to continue to at least slightly decline during the fourth fiscal quarter. Average spot pricing today is about 28% lower as compared to spot pricing at the peak last November. Let me now transition to our offshore operations. Segment operating income declined to approximately $15 million from $19 million during the prior quarter. Total revenue days decreased by about 8% as one rig was demobilized and became idle at the end of the second fiscal quarter. Also as expected, the average rig margin per day declined by about 24% to $14,265 during the third fiscal quarter. As we look at the fourth quarter of fiscal 2015, we expect revenue days to be relatively flat as one platform rig that was expected to become idle was recently contracted by another customer and continued generating revenue days while being prepared for the new project. We expect the segment's average rig margin per day to decline to approximately $10,500 during the fourth fiscal quarter. The expected average rig margin decline is mostly attributable to four rigs that are not performing operations but that are generating relatively low margins under standby type day rates, and one rig that is earning its temporarily reduced operating day rate to accommodate for a special project that is expected to expand the total duration of the overall project. The latter arrangement is mutually beneficial as it extends the total duration of the project while fully protecting our minimum term contract duration at fully priced day rates. Management contracts on platform rigs continued to favorably contribute to our offshore segment operating income. Their contribution during the third fiscal quarter was approximately $8 million and is expected to decline to approximately $6 million during the fourth fiscal quarter. Moving on to our international land operations, segment operating income increased by approximately $10 million to over $16 million during the third fiscal quarter. The increase was mostly attributable to early termination compensation earned during the quarter. Excluding the impact of $373 per day and $4,658 per day corresponding to early contract termination compensation during the second and third quarters respectively, the average rig margin per day increased from $10,524 to $13,086 per day. This increase was a result of strong performance during the quarter in all of the countries where we have active rates, even while dealing with several rigs in transition. Revenue days sequentially increased by about 2% to an average of over 20 active rigs during the third fiscal quarter. As of today, our international land segment has 17 active rigs, including 11 in Argentina, 2 in Colombia, 2 in the UAE, 1 in Ecuador and 1 in Bahrain. 23 rigs are idle, including 8 in Argentina, 6 in Colombia, 5 in Ecuador, 2 in Bahrain, and 2 in Tunisia. Thus, we expect international land quarterly revenue days to be down by 10% to 15% for the fourth fiscal quarter. We also expect the average rig margin per day to decline by about 30% to 35% as compared to the third fiscal quarter, excluding any impact from early contract terminations. We expect to generate early termination revenues of approximately $9 million during the fourth fiscal quarter in the segment. The expected daily rig margin decline in the segment is primarily due to expenses corresponding to several rigs that have become idle and two rigs that are scheduled to be demobilized out of Tunisia. Let me now comment on some corporate level details. Our liquidity position is very strong and we expect no change to our regular dividend dollar per share levels in the foreseeable future. Our capital expenditures estimate for fiscal 2015 remains at approximately $1.3 billion. Although we don't plan to provide a capital expenditures estimate for fiscal 2016 until our next conference call in November, at this point, we would expect the fiscal 2016 estimate to be significantly lower than the one for fiscal 2015. Our FlexRig construction cadence plan remains generally the same, with 12 new FlexRigs to be completed between now and the end of March of 2016. Including the long-term contracts for these 12 new FlexRigs, we already have secured term contracts for an average of approximately 137 rigs across our three segments during the fourth quarter of fiscal 2015. In addition, and also for all three segments combined, an average of about 122 rigs is already under contract for fiscal 2016 and an average of approximately 95 rigs for fiscal 2017. Given the soft market conditions, our backlog decreased from approximately $3.9 billion as of March 31, 2015 to approximately $3.5 billion as of June 30, 2015. The value of our backlog is expected to continue to decline during the fourth fiscal quarter as we earn related income through operations or through any additional, but at this time unexpected, early contract termination compensation. We now expect our total annual depreciation expense to be approximately $580 million during fiscal 2015 and our general and administrative expenses to be approximately $130 million. Interest expense after capitalized interest is still expected to be approximately $15 million for fiscal 2015. The effective income tax rate for the third fiscal quarter was 28.9%. This reduced rate was mostly a result of a favorable adjustment to our U.S. deferred state income tax rate caused by less activity in the states where we operate in as well as decreases to some of the state income tax rates. The effective tax rate for the fourth quarter of fiscal 2015 is expected to be approximately 34%. Our deferred income tax liability as of June 30, 2015 was approximately $1.33 billion. We still expect this liability to remain in the range of $1.3 billion and $1.4 billion through at least the end of fiscal 2017. With that, let me turn the call back to the John.

[John W. Lindsay:]

Thank you, again, Juan Pablo. And before we open the call to questions I want to make a few additional comments to frame up the challenges and opportunities ahead for H&P. The challenges are clear. Faced with a global oversupply of oil as well as other geopolitical and macroeconomic headwinds that intensify the supply-demand imbalance, the short-term outlook for the industry is unfavorable. However, a significant difference today compared to previous down cycles is that the U.S. may be in a position to become a global swing producer. In such an environment, the energy services landscape would most probably become more competitive with even greater pressure to reduce well cost, enhance productivity and add value for customers. We believe that type of a market is a great opportunity for H&P. Our long-term strategy has delivered a track record of innovation, performance and value creation for customers. Our people remain committed to this endeavor and we look forward to the opportunities ahead. So Lindy, we will now open the call for questions.

[Operator:]

We'll take our first question from Chase Mulvehill with SunTrust. Please go ahead. Your line is open.

[B. Chase Mulvehill:]

Hey. Good morning, fellas.

[John W. Lindsay:]

Good morning, Chase.

[B. Chase Mulvehill:]

So I guess in one of your recent presentations, you guys talked about renegotiating term day rates lower for additional term. Can you just kind of walk us through the kind of details here and kind of when you expect those to step back up?

[Juan Pablo Tardio:]

Yes, Chase. This is Juan Pablo. Those are relatively short-term type agreements. Within a year, we should be out of that type of arrangement, but we will see how the market goes. Again, we do believe that it is a mutually beneficial arrangement and we have fully protected the minimum duration of the term as well as that minimum duration at fully priced levels.

[B. Chase Mulvehill:]

Okay. All righty. Thanks for that color. And then if we kind of move to international real quick, is there any opportunities to move U.S. FlexRigs to international markets? And without just kind of identifying markets, I mean, what kind of expectations do you think that you could have over the next 12 to 18 months kind of potential to move rigs to international markets?

[John W. Lindsay:]

Sure. Chase, this is John. I think there are several opportunities. I'm sure you recall we did send 10 Flex3s to Argentina. Those were all existing Flex3s and that opportunity initially presented itself in, I guess, it was 2013. We had a little bit of a slow spot at that time. We had probably 20 idle AC rigs, and so we sourced those rigs out of the U.S., and so there's no doubt there's an opportunity. The FlexRigs have clearly performed well in every country that we've worked. The performance has been outstanding, so I think there's opportunities not only in South America, but I think there's also continued opportunities in the Middle East. So I do think this slowdown and our capability in having those rigs available in the U.S. does give us that opportunity to expand our international fleet.

[B. Chase Mulvehill:]

Okay. All right. Last kind of follow-up for me, on maintenance CapEx, you talked about fiscal 2016 CapEx being down significantly. How can we think about maintenance CapEx for fiscal 2016, assuming flat rig count environment?

[Juan Pablo Tardio:]

Yes, Chase, this Juan Pablo. We've said in the past that the $1.3 billion estimate for fiscal 2015, less than 20% was expected to be in maintenance CapEx. And so that's the only parameter that I can refer to at this point. Whether it's $200 million to $260 million for fiscal 2015, we'll see what the number is in the end. We'll have – if we, as you said, assuming that the activity remains stable, then we will probably an even lower level of maintenance CapEx for fiscal 2016.

[B. Chase Mulvehill:]

Great. All righty. That's all I have. Thanks, John. Thanks, Juan Pablo.

[John W. Lindsay:]

Thank you.

[Juan Pablo Tardio:]

Thank you.

[Operator:]

And we'll take our next question from Kurt Hallead with RBC Capital Markets. Please go ahead. Your line is open.

[Kurt Hallead:]

Thank you. Good morning.

[John W. Lindsay:]

Good morning, Kurt.

[Juan Pablo Tardio:]

Good morning, Kurt.

[Kurt Hallead:]

Hey. I just – you guys mentioned a little bit earlier in your presentation about the day rates to remain flat over the next several quarters and then the average would increase to previous levels predicated on a few different factors. I'm sorry, but I was a little bit slow in trying to follow how you were trying to express that. So could you state that one more time?

[Juan Pablo Tardio:]

Sure, Kurt. This is Juan Pablo. We were referring explicitly to rigs that are under term contracts, so it's not to all rigs, but only rigs that are under term contracts. And we were referring to the average rig margin per day. And as we looked at the impact of these renegotiations on that average rig margin per day for term contracts, we determined that that impact was under 5%. So within the next several months, probably less than a year, we would expect those temporary reductions to expire and to go back to prior fully-priced levels, which would yield again the type of margins where we were at before these reductions. So we would expect to get that approximately 5% back once, again, once we have these temporary reductions expire. Does that bring clarity?

[Kurt Hallead:]

Yeah. That does help a lot. Appreciate that. The follow-up question I have, John, you indicated kind of early on had given some indications of tone and tenor of the customer base and indicated that $40 – that the rig count would be unsustainable at a $40 oil price and I think we can understand that pretty well. But maybe digging a little bit deeper into some of this tone and tenor, so overall are you then getting the impression that the E&P mindset is that oil is going to remain around kind of current levels, $50-plus levels? And at these levels that there is no upside or no downside to activity? How would you characterize the viewpoints on that?

[John W. Lindsay:]

Well, Kurt, as always when you start talking about these kind of things and using numbers, it's easy to get – to not be as clear as you want to be. I really meant to say in the $40s. We're in the $40s. We're mid to high $40 range and again I think even in that price environment, we're more than likely going to see the behaviors that I mentioned, which is some rigs that were previously going to be reactivated on the back half of 2015 most likely won't be unless oil prices improve. The question is at what oil price? And again, I think we saw the industry beginning to move. You saw the rig count begin to flatten and you began to see more discussions regarding rigs in the spot market. But in this pricing environment, I just don't think you're going to see that. In fact, I think you could see the rig count pull back some. So again, it's a challenge. I think in order to see the rig count begin to improve we're going to have to see a stronger oil price environment than what we've seen. If you recall, and I think it was in the last round of earnings calls, there were some that were expecting a 200-rig increase by the end of the year and we said we just didn't see that. I mean we couldn't see how there could – that could happen. Now we weren't, at that time, of course, we weren't expecting oil to pull back into the $40s. I mean, the reality is I think if you went out and surveyed 10 different E&P operators, you would get a pretty wide range of expectation on pricing and I think a lot of folks are thinking oil prices are going to be lower as opposed to moving higher.

[Kurt Hallead:]

Okay.

[John W. Lindsay:]

But again, I'm not here to predict the oil price. I'm just telling you what we've heard from customers and others in the industry. I think you guys have heard the same thing.

[Kurt Hallead:]

Yeah. No, I appreciate that color. That's helpful. Thanks.

[John W. Lindsay:]

All right.

[Operator:]

And we'll take our next question from Byron Pope with Tudor, Pickering, Holt. Please go ahead. Your line is open.

[Byron K. Pope:]

Good morning.

[John W. Lindsay:]

Morning.

[Juan Pablo Tardio:]

Morning.

[Byron K. Pope:]

John, just wanted to get your thoughts on average rig revenue per day trends and understanding that you guys want to keep your fleet in quick response capability. And so if we, so whatever recovery scenario we want to assume, is it fair to think that as we see some of your vital AC rigs go back to work over the next 12, 18 months that that rig expense per day should gravitate back down closer to what it's been historically and call it the $13,000 or $13,300 range? Just somewhere in that historical range is still the appropriate way to think about your true rig expense per day, again, putting aside the cost that you guys are temporarily incurring to keep your fleet ready?

[John W. Lindsay:]

Right. Right. Well, and you saw that Juan Pablo had talked about our cost expectations for the next quarter. But you're right, I mean, part of the challenge, of course, is the rigs that are idle have an ongoing expense. And at the same time, your average number of rigs working is lower so you're denominator is smaller. So you just have a higher cost. But as rigs are idle longer, the expense is lower. We're not spending that same level of money that we are day 90 on as we are in the first 30 to 60 days.

[Byron K. Pope:]

Right.

[John W. Lindsay:]

So I think your expectation is right. I think and again we've talked about this and we're not going to throw a number out there, but $13,000 is achievable again in the future with more rigs running. I don't know exactly what that number of rig count is but I think as we begin to get more clarity over the next couple of quarters, we'll see that. I can tell you we're spending a lot of time and effort on the cost side and but, at the same time, like I had my remarks, we're going to make certain that we're spending and investing in the rigs in the way that we need to.

[Byron K. Pope:]

Okay. And then just a second quick question for me. It seemed as though at the peak of your newbuild orders, the lion's share of the rigs were going to be headed toward the Permian and the Eagle Ford. So as you think about the 12 remaining newbuilds to be delivered between now and next March, is it reasonable to think that the geographic mix of those is similar to what it has been?

[John W. Lindsay:]

Yeah. I think that's fair. I think about, I believe, nine of those are going to Permian and I think the others are going into Oklahoma.

[Byron K. Pope:]

Okay. Thanks, guys. Appreciate it.

[John W. Lindsay:]

All right. Thank you, Byron.

[Operator:]

And we'll take our next question from Brad Handler with Jefferies. Please go ahead. Your line is open.

[Bradley P. Handler:]

Thanks. Good morning, guys.

[John W. Lindsay:]

Morning.

[Juan Pablo Tardio:]

Good morning.

[Bradley P. Handler:]

I guess maybe it's coming back to the inquiries and the conversations. To what extent is the high-grading conversation, therefore, also kind of being put off? It sounds like it is but even if an operator wasn't planning on taking more rigs, I think that you had some optimism earlier that perhaps a high-grading process might have been relevant.

[John W. Lindsay:]

Brad, high-grading is still very relevant. I don't have insight into the number of legacy rigs, SCR mechanical rigs that are running today that are also under a term contract. But I think there's a fair amount of rigs that are in that category. And so, yes, those rigs we are in discussion with customers, with – hopefully the intent would be to replace those rigs. So I think the replacement cycle is alive and well and in some respects even more so because of the types of wells that are being drilled today. So I think that's going to happen but, again, a lot of that is going to relate to the number of those rigs that are rolling off of term. Does that answer your question?

[Bradley P. Handler:]

Yeah. Yeah. No, it absolutely does. Maybe I missed it, Juan Pablo, but in terms of the international in your fiscal fourth quarter – so I'm just jumping to international. I just thought, perhaps I missed it and so apologies. Could you describe again the basis for why the margins fall back to the $10,000-ish kind of a day level? Is that – you mentioned very good execution in fiscal 3Q. Are you just hedging against that being able to repeat in fiscal four or was there something more specific that weighed on the margin internationally?

[Juan Pablo Tardio:]

Sure, Brad. This is Juan Pablo. There are a couple of considerations that are most relevant in explaining the decline and the first one relates to several rigs becoming idle. Unfortunately, we've had close to half a dozen rigs that have become idle in recent months. And so we're dealing with a process of stacking those and dealing with those. And of course, there's expenses associated with that. The other consideration relates to two rigs that are not contracted being demobilized out of Tunisia. That too has an impact on margins, relatively significant impact on margins. So the combination of those two things are leading us to the type of decline that we're projecting.

[Bradley P. Handler:]

Okay. Just to follow up on that point is I think maybe about the first fiscal quarter of 2016 then, can we imagine that the cost that you've just described in both are – you finished spending them so there's a little bit lower rig count? Really I don't know if the two – do the two relate – so the two aren't working anyway. So are the costs out of the system then and so you might – one might naturally expect margins to rebound on the 17 active rigs in the first quarter of 2016? Is that logical?

[Juan Pablo Tardio:]

I think it is, Brad. I think everything else being equal, that is a fair expectation for us to see an improvement in margins during the following quarter. However, again – and that's everything else being equal, we'll have to see what else happens in the segment. And we'll certainly comment on that during our next conference call.

[Bradley P. Handler:]

Sure. Okay. Thanks, guys. I'll turn it back.

[John W. Lindsay:]

Thanks, Brad.

[Juan Pablo Tardio:]

Thank you.

[Operator:]

And we'll take our next question Waqar Syed with Goldman Sachs. Please go ahead. Your line is open.

[Waqar M. Syed:]

Thank you for taking my question. On the rigs that are idle right now, the Flexs, could you provide us with a breakdown of rigs between Flex4s, 5s and 3?

[John W. Lindsay:]

Sure. Waqar, we'll – let us look at it right quickly.

[Juan Pablo Tardio:]

Hold on, let me get a better handle on those numbers. So approximately 111 FlexRig 3s, 7 FlexRig 5s, and the rest are FlexRig 4s.

[Waqar M. Syed:]

Okay. And so the...

[Juan Pablo Tardio:]

I think you were talking only about the FlexRigs, so we do have seven conventional idled rigs as well.

[John W. Lindsay:]

Those are all 3,000 horsepower.

[Waqar M. Syed:]

Okay. And that – so this, the FlexRig number was 180 that you'd given, right, the idle FlexRig number?

[Juan Pablo Tardio:]

I think it was 179.

[Waqar M. Syed:]

179. Okay.

[Juan Pablo Tardio:]

Yeah.

[Waqar M. Syed:]

And then of these rigs, how many are pad drilling capable? And could you give a breakdown between the three as well?

[John W. Lindsay:]

Well, of the rigs that are – well of the rigs, over half of the rigs are pad capable. Of those particular, what's the number here – and I think the thing that's a key when you say they're pad capable right now in that, as an example, if it's a Flex3, many of the Flex3s have pad capability, have had that upgrade installed, but many of them don't. But we continue to upgrade Flex3's in the existing fleet to make them pad capable. So the number we would be giving you right now is a snapshot today. If you ask us that same question three months from now, the number's going to be higher. Juan Pablo, you want to go ahead and...

[Juan Pablo Tardio:]

Sure. I think the numbers are about 36 FlexRig 3s, about 41 FlexRig 4s, and 7 FlexRig 5s.

[Waqar M. Syed:]

Are pad capable, of the ones that are idle?

[Juan Pablo Tardio:]

And idle, yes.

[Waqar M. Syed:]

Okay. And my understanding is, gosh, maybe like $1 million of investment to maybe make any rig pad capable. Do you expense that cost? Do you capitalize that?

[Juan Pablo Tardio:]

We capitalize that.

[Waqar M. Syed:]

You capitalize that. Okay. Makes sense. And then what is the difference between day rate difference, maybe in percentage terms between rigs in the last quarter between the rigs on term contract, the day rate there or revenue per day there versus those on spot?

[Juan Pablo Tardio:]

Well, let me give you a general answer for that, Waqar. The day rates and pricing for term contracts has remained very steady except for what I mentioned earlier as relates to these temporary renegotiations that impacted margins by about 5%. So the day rates were only impacted by a few percentage points, a couple percentage points, maybe 2, 3.

[Waqar M. Syed:]

Okay.

[Juan Pablo Tardio:]

So those have remained flat while since November as I've mentioned, we've had a decline in the average spot pricing for our rigs of about 28%. I think it is fair to assume that at the peak the average rig – excuse me, the average day rates or pricing for rigs on term was similar. I think it was maybe a couple of percentage points higher than the average spot pricing at that point. So those are some data points for consideration.

[Waqar M. Syed:]

Okay.

[Juan Pablo Tardio:]

And of course, now, again I just want to make sure I clarify, the term day rates or average pricing that we saw at the peak last year has come down slightly temporarily and we expect it to come back up as I mentioned in the previous answer, right?

[Waqar M. Syed:]

Sure. Yeah. No, I understand that. John, just a broader question on cost. Like cost is, obviously cutting costs is going to become a big theme. For a land driller, where is the opportunity to cut costs? Like how can you guys – is it in G&A? Is it at the rig level? Where is the opportunity to cut costs?

[John W. Lindsay:]

Well, there's obviously efficiencies associated with the cost cutting savings. I mean, let's face it, the cost increases we've had are transitionary in nature as we've already described. Obviously the labor cost is the largest portion of that cost and as you know that's a direct cost passed through to the customer. So any wage decrease is going to be passed through so there's an offsetting revenue reduction. The maintenance and supply cost is the other side or the other larger piece or largest piece of the cost and, again, I think we're in as good a position as anyone to be able to manage that as effectively as possible with the fleet that we have, the size that we have and the fleet uniformity, but the fact is that, and you've probably heard me say this before, but the fact is the rigs are working harder and harder because they're drilling longer laterals and higher pump pressure and there's just more – the rigs are drilling faster wells, faster well cycle times so that's working against us, so to speak, on getting the maintenance and the supply costs down. So there's efforts that we have underway to work on that. Juan Pablo, do you have anything else to add on that? I mean, again, the biggest challenge we have right now, Waqar, is we've costs associated with rigs that are idle that aren't earning the revenue and so that's the challenge and there's fixed costs associated with that, that there's not anything we can do about at this stage of the game.

[Waqar M. Syed:]

Sure. Okay. Thank you very much. Thanks for the answers.

[John W. Lindsay:]

Okay. Thanks, Waqar.

[Operator:]

And we'll take our next question from Sean Meakim with JPMorgan.

[Sean C. Meakim:]

Hey, good morning.

[John W. Lindsay:]

Good morning, Sean.

[Sean C. Meakim:]

So just wanted to talk a little bit about newbuilds, the newbuild program. Historically, we've thought about the rigs as having pretty long lives, maybe 20, 30 years, and with the high-spec rigs that are coming out today, we're working them a lot harder, the shifts in technology kind of demand from the client side. Do you think that the life of recent builds is going to be much shorter, something like closer to 15 years, and then how does that influence – if you think that's the case, how does that influence you view on future demand for newbuilds as we look out beyond on the next couple years?

[John W. Lindsay:]

Well, Sean, we have, of course, our original 32 Flex3s that we built from 2002 to 2004. And again, you've probably heard us say this before, but we've continued to invest in those rigs and we've continued to make certain that the technology that they have is up to speed. The structures – we have an ongoing very detailed structural inspection process. The structures are very sound and so I don't know if it's a 15-year life or a 20-year life or a 30-year life. I mean, obviously, the market's going to dictate that. I would like to think that with the investments that we're making in these rigs that they're going to continue to work. I sure don't see any evidence that those first Flex3s that we have built are any less popular. Those rigs continue to work. Some have skid systems and some don't. So, Juan Pablo, I don't know if you have anything else to add on that?

[Juan Pablo Tardio:]

I'll just add the comment that for financial purposes, we depreciate our rigs in 15 years, straight line with a 10% salvage number and that number, that approach we believe is a fair one.

[John W. Lindsay:]

Sean, I think the other thing, as I think about your question, you are right, the rigs are working harder. It's more wear and tear on the assets and so, again, that's one of the things that we pride ourselves in. I think we do a very good job, is in asset integrity and taking care of those assets and supporting our people. Because it's not only the rig side of the equation on these much faster well cycles, it's also personnel and what they are required to do in that given well cycle. So there's also the organizational support that we provide our people that allow them to better maintain that equipment. Again, I think that's one of our significant competitive advantages.

[Sean C. Meakim:]

That's all very fair. I guess just sticking with kind of the newbuild theme, as we look forward here, we're talking now about potentially some softening of demand, maybe some evaporation of incremental. But if the rig count doesn't take another leg down, if we flat line here for several quarters, let's say, is there an opportunity as refleeting kind of runs its course that you could see incremental demand for newbuilds even in a world in which there are still other AC rigs that are still idle?

[John W. Lindsay:]

Well, I think we're – I don't know what the rig count is to have what you just described happen. I think it's significantly higher than 850 rigs. I would think it would at least need to be 1,000 or 1,100, 1,200 rigs. But I think, to again, to your point, not all AC rigs are created equal.

[Sean C. Meakim:]

Right.

[John W. Lindsay:]

And I think that's pretty evident. Over the last couple of years, there has remained 50 or 60 idle AC rigs that never worked. So those rigs obviously are not included in the equation. And then as we trend more towards a higher number of rigs drilling on pads and a higher number of rigs that require 7,500 psi, that have greater depth requirements, a lot of those things disqualify some of those – maybe describe them as lower tier AC assets. So again, it'll be interesting to watch. Now does the market – the other part of your question is, does the market get strong enough to have rates that will support newbuild economics? And we're a long way from that.

[Sean C. Meakim:]

Yeah. Yeah. That makes a lot of sense. Thanks, John. I appreciate it.

[John W. Lindsay:]

All right, Sean. Thanks.

[Operator:]

And our next question comes from Michael LaMotte with Guggenheim. Please go ahead. Your line is open.

[Michael LaMotte:]

Thanks. John, if I could follow up on your very last comment, the markets being a long way away from newbuild economics. Can you talk about just sort of philosophically how you feel about the infrastructure that you've built before newbuilding as we go into 2016? In previous downturns, you've maintained a minimum cadence of one rig a month to kind of maintain the integrity of that system, but...

[John W. Lindsay:]

Right.

[Michael LaMotte:]

...how are you thinking about that into next year?

[John W. Lindsay:]

Well, you heard us say that our desire is to keep that facility or that capability up and running and operating. I think the lowest we've been is one rig a month over the last – well, since 2006. And we talked about going to one rig a quarter. The great news right now is we don't have to make that decision now. That's part of the advantage of pushing our newbuilds out into 2016. But we'll have some level of manufacturing capability. We wouldn't close the entire facility down. But I don't know what it looks like right now, Michael. I mean, the reality is that the outlook is pretty difficult and again, we saw some improvement in oil prices and started to see a little pick up. It appeared in activity and now we're faced with what we're faced with. But again, I feel pretty good that we'll figure out some way to keep that facility working in some fashion, just don't know what that looks like today.

[Michael LaMotte:]

And maybe – I know aftermarket is the wrong term, but if I think about your ability to do maintenance on the rigs, prepare them for work overseas should those opportunities emerge, is that the kind of work scope that we could see that group doing if there were no contracts for newbuilds?

[John W. Lindsay:]

There's several opportunities. That's one of them, international, just other upgrades to rigs. And again, I said before, we continue to add pad systems to Flex3s and other upgrades, 7,500 psi systems and those types of things. So there's a lot of things in a market that continues to evolve and has higher and higher expectations for rigs; that's one of the ways to keep the facility operating.

[Michael LaMotte:]

Last one for me, you talked about the competitiveness and the fact that 90% plus the U.S. fleet is 1,500 horsepower, obviously pad capable. How do you think about automation, (56

[John W. Lindsay:]

Well, I think we're probably as well prepared as anybody with respect to automation. And I think it's obviously has an opportunity to do more and contribute more in the future. Again, I like and you've probably heard us say, I like our position. I like where we are in that space with the AC fleet that we have and with the footprint that we have and the knowledge that we have as an organization. So I feel pretty good about it, and I think it's got some likelihood, but it also has, just because of the level of performance that we are delivering today, as you know, it's harder and harder to get other technologies that are involved. But again, I think there's some possibility there.

[Michael LaMotte:]

Thank you.

[Operator:]

And we'll take our next question from Jeff Spittel with Clarkson Platou Securities. Please go ahead. Your line is open.

[Jeffrey D. Spittel:]

Thanks. Good morning, guys.

[John W. Lindsay:]

Good morning.

[Jeffrey D. Spittel:]

I know we're getting toward the end of the hour now so maybe just to look at that comment that you made about standbys and rigs being put back to work, as we saw for at least a fleeting moment a recovery in oil prices. And I guess from that and some other aspects of the conversation, is it fair to conclude I guess that you did see quite a bit of upside sensitivity to, all things considered, a relatively modest increase in crude prices as we went through the quarter, and obviously that isn't the case today, but maybe some cause for optimism there?

[John W. Lindsay:]

Jeff, I want to make certain I understood your question. So if we see an improvement in oil price we could see a corresponding – a fairly quick corresponding response. Is that what you're asking?

[Jeffrey D. Spittel:]

Yeah, that's kind of what I'm getting at, John. I guess from your comment that you did see a lot of rigs that were on standby rates get put back to work when we saw oil prices recover briefly during the quarter.

[John W. Lindsay:]

Yeah, I think that's – I mean, that's one element. That's one indicator. And again, just customer discussions and looking for rigs and high grades. In some cases it's a high grade. In other cases, it's an additional rig. And I think you probably would see fewer discussions on additional rigs and we'll continue to have discussions regarding high-grading or replacing rigs that are older that are not performing as well.

[Jeffrey D. Spittel:]

Sure. Okay. That makes sense. Thanks, guys. I'll turn it back.

[John W. Lindsay:]

All right, Jeff. Thanks.

[Juan Pablo Tardio:]

And Lindy, we may have time for one more question, please.

[Operator:]

Okay. We'll take our final question from Jim Wicklund with Credit Suisse, Please go ahead. Your line is open. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Good morning, guys. Thanks for letting me. I appreciate it.

[John W. Lindsay:]

Sure. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) You guys mentioned on a conference call a couple of years ago that you had 57 customers who are just fine with the fact that your rigs skid not walk. You talk about pad capable rigs. Have you all put any walking systems on any of your rigs? Do you feel any pressure to? And when you say pad capable what's the difference with you guys between pad capable and not pad capable?

[John W. Lindsay:]

Okay, Jim. That was a mouthful. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Last question. I won't do a follow-up.

[John W. Lindsay:]

Thank you. Well, I don't really know how to address the last part of your question. I mean, with us, we've, again, we've been utilizing skid systems on Flex3s for quite some time and, of course, Flex4s and Flex5s. I mean, you know the stats. Last year, we had 89 newbuilds and over two-thirds of those had pad capable systems as part of the investment. James Wicklund - Credit Suisse Securities (USA) LLC (Broker) And you're calling pad capable systems walking systems?

[John W. Lindsay:]

Well, no. It's interesting because a lot of people will reference a pad rig as walking even when the rig isn't a walking system, so I think there's some overlap in there. Our experience has been we have a family solutions with our FlexRig offering and there's upgrade capabilities within that. We've had a lot of traction over the year utilizing those. To answer your question, we don't have a walking system now. I think it's fair to say you've heard me say in the past that if and when we get to that point where it's a difference between having a job and not having job, obviously, it's not a breakthrough technology. That technology has been around for a long time. So we would put a walking system on a rig if it were the difference between having a large share of the market and not having. So that's really the bottom line for us is that customer demand has been pretty significant. We continue to upgrade rigs with our system, our skid systems and we have customers that love it, so... James Wicklund - Credit Suisse Securities (USA) LLC (Broker) Okay, gentlemen. I appreciate it. And thanks for squeezing me in at the end. I appreciate it.

[John W. Lindsay:]

All right. Thanks, Jim.

[Juan Pablo Tardio:]

Thank you, Jim, and one more quick comment. I may have used the round reference of $130 million as it relates to operating income for the third fiscal quarter. A more accurate number would be $132.8 million. So with that, thank you, everybody, and have a great day. Goodbye.

[Operator:]

And that does conclude today's program. You may disconnect at this time. Thank you and have a great day.